Mixtures of oil, gas, and water are frequently produced from oilfields and processes for treating these mixtures to separate the oil, gas and water are well known, e.g. gravity separation in tanks. Typically the oil is separated and recovered. The gas component may be separated and recovered separately or, alternatively, the gas may be re-injected, e.g. above an oil-bearing zone or into an oil-bearing zone. If the gas is injected, it may be injected as-recovered or as a mixture with, e.g. nitrogen, carbon dioxide, or a gaseous hydrocarbon to adjust the specific gravity of the gas to a suitable level. The water component may similarly be recovered for re-injection or disposal by other means.
Following separation, the components destined for re-injection are carried from the central separation facility to the re-injection sites along various conduits to the injection lines. It has been found, during this processing and transport, especially when corrosion inhibitors are used in the conduits, e.g. those leading from the wells to the central processing facility, that, over a period of time, heavy hydrocarbon materials and finely divided inorganic solids form deposits on the inner surfaces of the conduits. These deposits typically comprise finely-divided inorganic particles which may include clays, sand, hydraulic fracturing proppant, formation fines, and precipitates of materials including metal components such as iron sulfide. These particles become coated with corrosion inhibitor and/or other hydrocarbon materials. The coated particles may then agglomerate or accumulate additional quantities of heavy hydrocarbon material in the conduits, settling tank or other process areas. This forms a deposit which is sometimes referred to in the industry as “schmoo”. This deposit is a paste, solid, or oily substance which adheres to surfaces with which it comes into contact, and is difficult to remove. In particular, the deposit is difficult to remove from the inner surfaces of flow conduits, e.g. flowlines, water/gas injection lines, and wellbore surfaces. The deposit may be removed, at least partially, by pigging flowlines which are above a suitable diameter and configuration that pigs can be run through the lines. Other lines, such as injection lines into wells, small diameter flowlines, the settling tank surfaces, and formation surfaces are not routinely accessible by pigging operations and, accordingly, the deposit accumulates on their contact surfaces. Even cleaning of conduits by pigging can in some cases leave a thin film of the deposit on the inner conduit surface.
The hydrocarbon/particulate deposit is problematic for a number of reasons. The deposit forms a layer on surfaces and bacteria have been found which generate corrosive sulfides and other compounds between the deposit and in contact with the surface. This can result in accelerated corrosion of the surface behind the deposit, the formation of pits and even failure of the surface, e.g. failure of a pipe. The repair or replacement of pipework or other oilfield surfaces is expensive.
The deposited material can also accumulate to such a thickness that it flakes off the surface and deposits or blocks conduits or equipment downstream. For example, the deposit can flake away from the inner surface of a pipe and lodge in the lower portion of a well or line causing a blockage. This can require expensive cleaning operations such as the use of coiled tubing with the injection of organic solvents such as mixtures of diesel oil and xylene. Furthermore, the downtime of the apparatus during cleaning can have a significant commercial impact. This type of deposit is particularly common in wells which are used for alternating water and gas injection. In these wells, the deposit can dry on the inner surfaces of the tubing during gas injection and subsequently crack and be carried downstream or fall into the wellbore, thereby eventually plugging the wellbore. This cracking and dislodging of the deposited material is particularly prevalent when the conduit changes back to a liquid flow following a period of gas flow (during which the deposit dries out).
In view of the difficulties created by this type of deposit, an ongoing search has been directed to the development of a method for the removal of such deposits without the necessity for a pigging or coiled tubing operations.
Mixtures of alkyl polyglycosides and linear ethoxylates in aqueous sodium hydroxide have been investigated as possible compounds to remove these deposits (Bohon et al., NACE International, 98073 (1998), “Novel Chemical Dispersant for Removal of Organic/Inorganic “Schmoo” Scale in Produced Water Injection Systems”).
In some cases the known compositions are incompatible with polyacrylamide compounds that may be used in enhanced oil recovery (EOR) applications.
Similar mixtures of alkyl polyglycoside, ethoxylated alcohol, alkali, and alkyl alcohol are described for the removal of hydrocarbon/inorganic particulate deposits from both pipes (in U.S. Pat. No. 5,996,692) and tanks (in WO 99/41343).
Alternative mixtures comprising specific bis-quaternary compounds having an amido moiety have also been investigated for removal of this type of deposit in WO 2009/076258.